Consolidating Agent Emulsions and Associated Methods

ABSTRACT

Consolidation fluids comprising: an aqueous base fluid comprising a hardening agent; an emulsified resin having an aqueous external phase and an organic internal phase; a silane coupling agent; and a surfactant. The consolidation fluid itself may be emulsified and further comprise an emulsifying agent. The consolidation fluid may also be foamed in some cases.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of U.S. patentapplication Ser. No. 11/351,931, Attorney Docket No. HES2005-IP-018415U1, entitled “Consolidating Agent Emulsions and AssociatedMethods,” filed on Feb. 10, 2006, the entirety of which is hereinincorporated by reference.

BACKGROUND

The present invention relates to methods and compositions useful intreating subterranean formations, and more particularly, toconsolidating relatively unconsolidated portions of subterraneanformations and minimizing the flow back of unconsolidated particulatematerial (referred to collectively herein as “particulate migration.”)This invention also relates to modifying the stress-activated reactivityof subterranean fracture faces and other surfaces in subterraneanformations.

In the production of hydrocarbons from a subterranean formation, thesubterranean formation preferably should be sufficiently conductive topermit desirable fluids, such as oil and gas, to flow to a well borethat penetrates a subterranean formation. One type of treatment that maybe used to increase the conductivity of a subterranean formation ishydraulic fracturing. Hydraulic fracturing operations generally involvepumping a treatment fluid (e.g., a fracturing fluid or a “pad” fluid)into a well bore that penetrates a subterranean formation at asufficient hydraulic pressure to create or enhance one or more fracturesin the subterranean formation. The fluid used in the treatment maycomprise particulates, often referred to as “proppant particulates,”that are deposited in the resultant fractures. These proppantparticulates are thought to prevent the fractures from fully closingupon the release of hydraulic pressure, forming conductive channelsthrough which fluids may flow to a well bore. The term “proppedfracture” as used herein refers to a fracture (naturally-occurring orotherwise) in a portion of a subterranean formation that contains atleast a plurality of proppant particulates. The term “proppant pack”refers to a collection of proppant particulates within a fracture.

A type of particulate migration that may affect fluid conductivity inthe formation is the flow back of unconsolidated particulate material(e.g., formation fines, proppant particulates, etc.) through theconductive channels in the subterranean formation, which can, forexample, clog the conductive channels and/or damage the interior of theformation or equipment. There are several known techniques used tocontrol particulate migration, some of which may involve the use ofconsolidating agents. The term “consolidating agent” as used hereinincludes any compound that is capable of minimizing particulatemigration in a subterranean formation and/or modifying thestress-activated reactivity of subterranean fracture faces and othersurfaces in subterranean formations.

One well-known technique used to control particulate migration insubterranean formations is commonly referred to as “gravel packing,”which involves the placement of a filtration bed of gravel particulatesin the subterranean formation that acts as a barrier to preventparticulates from flowing into the well bore. These gravel packingoperations may involve the use of consolidating agents to bind thegravel particulates together in order to form a porous matrix throughwhich formation fluids can pass.

In some situations, a hydraulic fracturing treatment and agravel-packing treatment may be combined into a single treatment(commonly referred to as FRACPAC™ operations). In such “frac pack”operations, the fracturing and gravel-packing treatments are combinedand may generally be completed with a gravel pack screen assembly inplace with the hydraulic fracturing treatment being pumped through theannular space between the casing and screen. In this situation, thehydraulic fracturing treatment ends in a screen-out condition, creatingan annular gravel pack between the screen and casing. In other cases,the fracturing treatment may be performed prior to installing the screenand placing a gravel pack.

Another technique that may be used to control particulate migrationinvolves coating proppant particulates with a consolidating agent tofacilitate their consolidation within the formation and to prevent theirsubsequent flow-back through the conductive channels in the subterraneanformation.

Another method used to control particulate migration involvesconsolidating unconsolidated portions of subterranean zones intorelatively stable permeable masses by applying a consolidating agent toan unconsolidated portion of the subterranean formation. One example ofthis method is applying a resin to a portion of the zone, followed by aspacer fluid and then a catalyst. Such resin application may beproblematic when, for example, an insufficient amount of spacer fluid isused between the application of the resin and the application of theexternal catalyst. In that case, the resin may come into contact withthe external catalyst earlier in the process such as in the well boreitself rather than in the unconsolidated subterranean formation.Furthermore, there may be uncertainty as to whether there is adequatecontact between the resin and the catalyst. The terms “catalyst,”“hardening agent,” and “curing agent” may be used herein interchangeablyand collectively may refer to a composition that effects the hardeningof a resin composition by any means or mechanism. Another example ofthis method involves applying a tackifying composition (aqueous ornon-aqueous) to a portion of the formation in an effort to reduce themigration of particulates therein. Whereas a curable resin compositionproduces a hard mass, the use of a tackifying composition is thought toresult in a more malleable consolidated mass.

Although consolidating agents are used frequently, they may be difficultto handle, transport and clean-up due to their inherent tendency tostick to equipment or anything else with which they may come intocontact. Therefore, it would be desirable to provide compositions andmethods that would, among other things, help ease the handling,transport and clean up when using consolidating agents.

One additional problem that can negatively impact conductivity andfurther complicate the effects of particulate migration is the tendencyof mineral surfaces in a subterranean formation to undergo chemicalreactions caused, at least in part, by conditions created by mechanicalstresses on those minerals (e.g., fracturing of mineral surfaces,compaction of mineral particulates). These reactions are herein referredto as “stress-activated reactions” or “stress-activated reactivity.” Asused herein, the term “mineral surface in a subterranean formation” andderivatives thereof refer to any surface in a subterranean formationcomprised of minerals and/or the surface of a particulate. Theseminerals may comprise any mineral found in subterranean formations,including silicate minerals (e.g., quartz, feldspars, clay minerals),carbonaceous minerals, metal oxide minerals, and the like. The mineralsurface in a subterranean formation treated in the methods of thepresent invention may have been formed at any time. The term “modifyingthe stress-activated reactivity of a mineral surface” and itsderivatives as used herein refers to increasing or decreasing thetendency of a mineral surface in a subterranean formation to undergo oneor more stress-activated reactions, or attaching a compound to themineral surface that is capable of participating in one or moresubsequent reactions with a second compound.

One type of reaction caused, at least in part, by conditions created bymechanical stresses on minerals may be referred to as a diagenicreaction, which also may be known as a “diageneous reaction.” As usedherein, the terms “diagenic reaction,” “diagenic reactivity,” and“diagenesis” or any derivatives thereof include chemical and physicalprocesses that move a portion of a mineral sediment and/or convert themineral sediment into some other mineral form in the presence of water.A mineral sediment that has been so moved or converted is hereinreferred to as a “diagenic product.” Any mineral sediment may besusceptible to these diagenic reactions, including silicate minerals(e.g., quartz, feldspars, scale, clay minerals), carbonaceous minerals,metal oxide minerals, and the like.

Two mechanisms that diagenic reactions are thought to involve arepressure solution and precipitation processes. Where two water-wettedmineral surfaces are in contact with each other at a point under strain,the localized mineral solubility near that point is thought to increase,causing the minerals to dissolve. Minerals in solution may diffusethrough the water film outside of the region where the mineral surfacesare in contact (e.g., in the pore spaces of a proppant pack), where theymay precipitate out of solution. The dissolution and precipitation ofminerals in the course of these reactions may reduce the conductivity ofthe formations by, among other things, clogging the conductive channelsin the formation with mineral precipitate and/or collapsing thoseconductive channels by dissolving solid minerals in the surfaces ofthose channels.

Moreover, in the course of a fracturing treatment, new mineral surfacesmay be created in the “walls” surrounding the open space of thefracture. These new walls created in the course of a fracturingtreatment are herein referred to as “fracture faces.” Such fracturefaces may exhibit different types and levels of reactivity, for example,stress-activated reactivity. In some instances, fracture faces mayexhibit an increased tendency to undergo diagenic reactions. In otherinstances, fracture faces also may exhibit an increased tendency toreact with substances in formation fluids and/or treatment fluids thatare in contact with those fracture faces, such as water, polymers (e.g.,polysaccharides, biopolymers, surfactants, etc.), and other substancescommonly found in these fluids, whose molecules may become anchored tothe fracture face. This reactivity may further decrease the conductivityof the formation through, inter alia, increased diagenic reactionsand/or the obstruction of conductive fractures in the formation by anymolecules that have become anchored to the fracture faces.

SUMMARY

The present invention relates to methods and compositions useful forminimizing particulate migration. This invention also relates tomodifying the stress-activated reactivity of subterranean fracture facesand other surfaces in subterranean formations.

In one embodiment, the present invention provides a method comprisingproviding a consolidating agent emulsion composition comprising anaqueous fluid, an emulsifying agent, and a consolidating agent; andintroducing the consolidating agent emulsion composition into at least aportion of a subterranean formation.

In another embodiment, the present invention provides a methodcomprising providing a consolidating agent emulsion compositioncomprising an aqueous fluid, an emulsifying agent, and a consolidatingagent; introducing the consolidating agent emulsion composition into atleast a portion of a propped fracture that comprises proppantparticulates; allowing the consolidating agent to at least partiallyconsolidate at least a portion of the propped fracture.

In yet another embodiment, the present invention provides a methodcomprising providing a consolidating agent emulsion compositioncomprising an aqueous fluid, an emulsifying agent, and a consolidatingagent that comprises a resin composition; introducing the consolidatingagent emulsion composition into at least a portion of a subterraneanformation; and allowing the consolidating agent to at least partiallyconsolidate at least a portion of the subterranean formation.

The features and advantages of the present invention will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of theinvention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 is a micrograph image of untreated proppant particulates.

FIG. 2 is a micrograph image of untreated proppant particulates afterbeing subjected to a stress load of 10,000 psi at 250° F.

FIG. 3 is a micrograph image of proppant particulates that have beentreated with a consolidating agent emulsion in accordance with anembodiment of the present invention after being subjected to a stressload of 10,000 psi at 250° F.

FIG. 4 is a micrograph image of a Salt Wash South Core that has beentreated with a consolidating agent emulsion in accordance with anembodiment of the present invention.

FIG. 5 is a micrograph image of a Salt Wash South Core that has beentreated with a consolidating agent emulsion in accordance with anembodiment of the present invention.

FIG. 6 illustrates the unconfined compressive strength of sample sandpacks treated with a consolidating agent emulsion of the presentinvention.

FIG. 7 illustrates the regained permeability of sample sand packstreated with a consolidating agent emulsion of the present invention.

FIG. 8 is a CT scan image of a Castlegate Core sample that was subjectedto pretreatment flow and subsequently treated with a consolidating agentemulsion in accordance with an embodiment of the present invention.

FIG. 9 is a CT scan image of a Castlegate Core sample that has beentreated with a consolidating agent emulsion in accordance with anembodiment of the present invention.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to methods and compositions useful forminimizing particulate migration. This invention also relates tomodifying the stress-activated reactivity of subterranean fracture facesand other surfaces in subterranean formations.

One of the many potential advantages of the methods and compositions ofthe present invention is that they may allow, inter alia, for theconsolidation of relatively unconsolidated portions of subterraneanformations and may also minimize the flow back of unconsolidatedparticulate material. As a result, in some embodiments, it may bepossible to utilize larger sized proppant particulates that providehigher conductivity, without damage to the proppant pack due toformation fines movement and without compromising proppant flow backcontrol requirements. It is also possible, in some embodiments, tominimize the amount of consolidating agent that might otherwise berequired though the use of a consolidating agent emulsion, to achieve,inter alia, good strength performance and high regained permeability ofthe subterranean formation.

In addition, in some embodiments, the consolidating agent emulsions ofthe present invention may also eliminate the need for an expensiveand/or flammable solvent that might otherwise be necessary when usingconsolidating agents and may thereby reduce possible undesirable safetyand environmental concerns related to the use and disposal of suchsolvents. In some embodiments, the consolidating agent emulsions mayalso reduce the possibility of oil sheen, which may be of particularimportance in gulf coast regions. Furthermore, the consolidating agentemulsions of the present invention may also allow for relatively easyclean up of equipment and reduced potential damage to equipment due tothe buildup of the consolidation agent on the equipment.

A. Examples of Certain Embodiments of the Consolidating Agent Emulsionsof the Present Invention

The consolidating agent emulsions of the present invention comprise anaqueous fluid, an emulsifying agent, and a consolidating agent. In someembodiments, these consolidating agent emulsions have an aqueousexternal phase and organic based internal phase. The term “emulsion” andany derivatives thereof as used herein refers to a mixture of two ormore immiscible phases and includes, but is not limited to, dispersionsand suspensions.

1. Examples of Suitable Aqueous Fluids

The consolidating agent emulsions of the present invention comprise anaqueous external phase comprising an aqueous fluid. Suitable aqueousfluids that may be used in the consolidating agent emulsions of thepresent invention include fresh water, salt water, brine, seawater, orany other aqueous fluid that, preferably, does not adversely react withthe other components used in accordance with this invention or with thesubterranean formation. One should note, however, that if long-termstability of the emulsion is desired, in some embodiments, the preferredaqueous fluid may be one that is substantially free of salts. It iswithin the ability of one skilled in the art with the benefit of thisdisclosure to determine if and how much salt may be tolerated in theconsolidating agent emulsions of the present invention before it becomesproblematic for the stability of the emulsion. The aqueous fluid may bepresent in the consolidating agent emulsions of the present invention inan amount in the range of about 20% to about 99.9% by weight of theconsolidating agent emulsion composition. In some embodiments, theaqueous fluid may be present in the consolidating agent emulsions of thepresent invention in an amount in the range of about 60% to about 99.9%by weight of the consolidating agent emulsion composition. In someembodiments, the aqueous fluid may be present in the consolidating agentemulsions of the present invention in an amount in the range of about95% to about 99.9% by weight of the consolidating agent emulsioncomposition. Other ranges may be suitable as well, depending on theother components of the emulsion.

2. Examples of Suitable Types of Consolidating Agents

The consolidating agents suitable for use in the compositions andmethods of the present invention generally comprise any compound that iscapable of minimizing particulate migration and/or modifying thestress-activated reactivity of subterranean fracture faces and othersurfaces in subterranean formations. In some embodiments, theconsolidating agent may comprise compounds such as non-aqueoustackifying agents and resins. The consolidating agents may be present inthe consolidating agent emulsions of the present invention in an amountin the range of about 0.1% to about 80% by weight of the consolidatingagent emulsion composition. In some embodiments, the consolidating agentmay be present in the consolidating agent emulsions of the presentinvention in an amount in the range of about 0.1% to about 40% by weightof the composition. In some embodiments, the consolidating agent may bepresent in the consolidating agent emulsions of the present invention inan amount in the range of about 0.1% to about 5% by weight of thecomposition. The type and amount of consolidating agent included in aparticular composition or method of the invention may depend upon, amongother factors, the composition and/or temperature of the subterraneanformation, the chemical composition of formations fluids, flow rate offluids present in the formation, the effective porosity and/orpermeability of the subterranean formation, pore throat size anddistribution, and the like. Furthermore, the concentration of theconsolidating agent can be varied, inter alia, to either enhancebridging to provide for a more rapid coating of the consolidating agentor to minimize bridging to allow deeper penetration into thesubterranean formation. It is within the ability of one skilled in theart, with the benefit of this disclosure, to determine the type andamount of consolidating agent to include in the consolidating agentemulsions of the present invention to achieve the desired results.

The consolidating agents suitable for use in the present invention maybe provided in any suitable form, including in a particle form, whichmay be in a solid form and/or a liquid form. In those embodiments wherethe consolidating agent is provided in a particle form, the size of theparticle can vary widely. In some embodiments, the consolidating agentparticles may have an average particle diameter of about 0.01micrometers (“μm”) to about 300 μm. In some embodiments, theconsolidating agent particles may have an average particle diameter ofabout 0.01 μm to about 100 μm. In some embodiments, the consolidatingagent particles may have an average particle diameter of about 0.01 μMto about 10 μm. The size distribution of the consolidating agentparticles used in a particular composition or method of the inventionmay depend upon several factors including, but not limited to, the sizedistribution of the particulates present in the subterranean formation,the effective porosity and/or permeability of the subterraneanformation, pore throat size and distribution, and the like.

In some embodiments, it may desirable to use a consolidating agentparticle with a size distribution such that the consolidating agentparticles are placed at contact points between formation particulates.For example, in some embodiments, the size distribution of theconsolidating agent particles may be within a smaller size range, e.g.of about 0.01 μm to about 10 μm. It may be desirable in some embodimentsto provide consolidating agent particles with a smaller particle sizedistribution, inter alia, to promote deeper penetration of theconsolidating agent particles through a body of unconsolidatedparticulates or in low permeability formations.

In other embodiments, the size distribution of the consolidating agentparticles may be within a larger range, e.g. of about 30 μm to about 300μm. It may be desirable in some embodiments to provide consolidatingagent particles with a larger particle size distribution, inter alia, topromote the filtering out of consolidating agent particles at or nearthe spaces between neighboring unconsolidated particulates or in highpermeability formations. A person of ordinary skill in the art, with thebenefit of this disclosure, will be able to select an appropriateparticle size distribution for the consolidating agent particlessuitable for use in the present invention and will appreciate thatmethods of creating consolidating agent particles of any relevant sizeare well known in the art.

a. Non-Aqueous Tackifying Agents

In some embodiments of the present invention, the consolidating agentmay comprise a non-aqueous tackifying agent. A particularly preferredgroup of non-aqueous tackifying agents comprises polyamides that areliquids or in solution at the temperature of the subterranean formationsuch that they are, by themselves, non-hardening when introduced intothe subterranean formation. A particularly preferred product is acondensation reaction product comprised of commercially availablepolyacids and a polyamine. Such commercial products include compoundssuch as mixtures of C₃₆ dibasic acids containing some trimer and higheroligomers and also small amounts of monomer acids that are reacted withpolyamines. Other polyacids include trimer acids, synthetic acidsproduced from fatty acids, maleic anhydride, acrylic acid, and the like.Such acid compounds are commercially available from companies such asWitco Corporation, Union Camp, Chemtall, and Emery Industries. Thereaction products are available from, for example, ChampionTechnologies, Inc. and Witco Corporation.

Additional compounds which may be used as non-aqueous tackifying agentsinclude liquids and solutions of, for example, polyesters,polycarbonates, silyl-modified polyamide compounds, polycarbamates,urethanes, natural resins such as shellac, and the like.

Other suitable non-aqueous tackifying agents are described in U.S. Pat.Nos. 5,853,048 and 5,833,000 both issued to Weaver, et al., and U.S.Patent Publication Nos. 2007/0131425 and 2007/0131422, the relevantdisclosures of which are herein incorporated by reference.

Non-aqueous tackifying agents suitable for use in the present inventionmay either be used such that they form a non-hardening coating on asurface or they may be combined with a multifunctional material capableof reacting with the non-aqueous tackifying agent to form a hardenedcoating. A “hardened coating” as used herein means that the reaction ofthe tackifying compound with the multifunctional material will result ina substantially non-flowable reaction product that exhibits a highercompressive strength in a consolidated agglomerate than the tackifyingcompound alone with the particulates. In this instance, the non-aqueoustackifying agent may function similarly to a hardenable resin.

Multifunctional materials suitable for use in the present inventioninclude, but are not limited to, aldehydes, dialdehydes such asglutaraldehyde, hemiacetals or aldehyde releasing compounds, diacidhalides, dihalides such as dichlorides and dibromides, polyacidanhydrides such as citric acid, epoxides, furfuraldehyde,glutaraldehyde, aldehyde condensates, and silyl-modified polyamidecompounds and the like, and combinations thereof. Suitablesilyl-modified polyamide compounds that may be used in the presentinvention are those that are substantially self-hardening compositionscapable of at least partially adhering to a surface or to a particulatein the unhardened state, and that are further capable of self-hardeningthemselves to a substantially non-tacky state to which individualparticulates such as formation fines will not adhere to, for example, information or proppant pack pore throats. Such silyl-modified polyamidesmay be based, for example, on the reaction product of a silatingcompound with a polyamide or a mixture of polyamides. The polyamide ormixture of polyamides may be one or more polyamide intermediatecompounds obtained, for example, from the reaction of a polyacid (e.g.,diacid or higher) with a polyamine (e.g., diamine or higher) to form apolyamide polymer with the elimination of water.

In some embodiments of the present invention, the multifunctionalmaterial may be mixed with the tackifying compound in an amount of about0.01% to about 50% by weight of the tackifying compound to effectformation of the reaction product. In other embodiments, themultifunctional material is present in an amount of about 0.5% to about1% by weight of the tackifying compound. Suitable multifunctionalmaterials are described in U.S. Pat. No. 5,839,510 issued to Weaver, etal., the relevant disclosure of which is herein incorporated byreference.

b. Resins

In some embodiments of the present invention, the consolidating agentmay comprise a resin. The term “resin” as used herein refers to any ofnumerous physically similar polymerized synthetics or chemicallymodified natural resins including thermoplastic materials andthermosetting materials. Resins suitable for use in the presentinvention include substantially all resins known and used in the art.

One type of resin suitable for use in the compositions and methods ofthe present invention is a two-component epoxy based resin comprising aliquid hardenable resin component and a liquid hardening agentcomponent. The liquid hardenable resin component is comprised of ahardenable resin and an optional solvent. The solvent may be added tothe resin to reduce its viscosity for ease of handling, mixing andtransferring. It is within the ability of one skilled in the art withthe benefit of this disclosure to determine if and how much solvent maybe needed to achieve a viscosity suitable to the subterraneanconditions. Factors that may affect this decision include geographiclocation of the well, the surrounding weather conditions, and thedesired long-term stability of the consolidating agent emulsion. Analternate way to reduce the viscosity of the hardenable resin is to heatit. The second component is the liquid hardening agent component, whichis comprised of a hardening agent, an optional silane coupling agent, asurfactant, an optional hydrolyzable ester for, among other things,breaking gelled fracturing fluid films on proppant particulates, and anoptional liquid carrier fluid for, among other things, reducing theviscosity of the hardening agent component.

Examples of hardenable resins that can be used in the liquid hardenableresin component include, but are not limited to, organic resins such asbisphenol A diglycidyl ether resins, butoxymethyl butyl glycidyl etherresins, bisphenol A-epichlorohydrin resins, bisphenol F resins,polyepoxide resins, novolak resins, polyester resins, phenol-aldehyderesins, urea-aldehyde resins, furan resins, urethane resins, glycidylether resins, other epoxide resins and combinations thereof. In someembodiments, the hardenable resin may comprise a urethane resin.Examples of suitable urethane resins may comprise a polyisocyanatecomponent and a polyhydroxy component. Examples of suitable hardenableresins, including urethane resins, that may be suitable for use in themethods of the present invention include those described in U.S. Pat.No. 6,582,819 issued to McDaniel, et al., U.S. Pat. No. 4,585,064 issuedto Graham, et al., U.S. Pat. No. 6,677,426 issued to Noro, et al., andU.S. Pat. No. 7,153,575 issued to Anderson, et al., the relevantdisclosures of which are herein incorporated by reference.

The hardenable resin may be included in the liquid hardenable resincomponent in an amount in the range of about 5% to about 100% by weightof the liquid hardenable resin component. It is within the ability ofone skilled in the art with the benefit of this disclosure to determinehow much of the liquid hardenable resin component may be needed toachieve the desired results. Factors that may affect this decisioninclude which type of liquid hardenable resin component and liquidhardening agent component are used.

Any solvent that is compatible with the hardenable resin and achievesthe desired viscosity effect may be suitable for use in the liquidhardenable resin component. Suitable solvents may include butyl lactate,dipropylene glycol methyl ether, dipropylene glycol dimethyl ether,dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butylether, diethyleneglycol butyl ether, propylene carbonate, methanol,butyl alcohol, d'limonene, fatty acid methyl esters, and combinationsthereof. Other preferred solvents may include aqueous dissolvablesolvents such as, methanol, isopropanol, butanol, glycol ether solvents,and combinations thereof. Suitable glycol ether solvents include, butare not limited to, diethylene glycol methyl ether, dipropylene glycolmethyl ether, 2-butoxy ethanol, ethers of a C₂ to C₆ dihydric alkanolcontaining at least one C₁ to C₆ alkyl group, mono ethers of dihydricalkanols, methoxypropanol, butoxyethanol, hexoxyethanol, and isomersthereof. Selection of an appropriate solvent is dependent on the resincomposition chosen and is within the ability of one skilled in the artwith the benefit of this disclosure.

As described above, use of a solvent in the liquid hardenable resincomponent is optional but may be desirable to reduce the viscosity ofthe hardenable resin component for ease of handling, mixing, andtransferring. However, as previously stated, it may be desirable in someembodiments to not use such a solvent for environmental or safetyreasons. It is within the ability of one skilled in the art, with thebenefit of this disclosure, to determine if and how much solvent isneeded to achieve a suitable viscosity. In some embodiments, the amountof the solvent used in the liquid hardenable resin component may be inthe range of about 0.1% to about 30% by weight of the liquid hardenableresin component. Optionally, the liquid hardenable resin component maybe heated to reduce its viscosity, in place of, or in addition to, usinga solvent.

Examples of the hardening agents that can be used in the liquidhardening agent component include, but are not limited to,cyclo-aliphatic amines, such as piperazine, derivatives of piperazine(e.g., aminoethylpiperazine) and modified piperazines; aromatic amines,such as methylene dianiline, derivatives of methylene dianiline andhydrogenated forms, and 4,4′-diaminodiphenyl sulfone; aliphatic amines,such as ethylene diamine, diethylene triamine, triethylene tetraamine,and tetraethylene pentaamine; imidazole; pyrazole; pyrazine; pyrimidine;pyridazine; 1H-indazole; purine; phthalazine; naphthyridine;quinoxaline; quinazoline; phenazine; imidazolidine; cinnoline;imidazoline; 1,3,5-triazine; thiazole; pteridine; indazole; amines;polyamines; amides; polyamides; 2-ethyl-4-methyl imidazole; andcombinations thereof. The chosen hardening agent often effects the rangeof temperatures over which a hardenable resin is able to cure. By way ofexample and not of limitation, in subterranean formations having atemperature of about 60° F. to about 250° F., amines and cyclo-aliphaticamines such as piperidine, triethylamine,tris(dimethylaminomethyl)phenol, and dimethylaminomethyl)phenol may bepreferred. In subterranean formations having higher temperatures,4,4′-diaminodiphenyl sulfone may be a suitable hardening agent.Hardening agents that comprise piperazine or a derivative of piperazinehave been shown capable of curing various hardenable resins fromtemperatures as low as about 50° F. to as high as about 350° F.

The hardening agent used may be included in the liquid hardening agentcomponent in an amount sufficient to at least partially harden the resincomposition. In some embodiments of the present invention, the hardeningagent used is included in the liquid hardening agent component in therange of about 0.1% to about 95% by weight of the liquid hardening agentcomponent. In other embodiments, the hardening agent used may beincluded in the liquid hardening agent component in an amount of about15% to about 85% by weight of the liquid hardening agent component. Inother embodiments, the hardening agent used may be included in theliquid hardening agent component in an amount of about 15% to about 55%by weight of the liquid hardening agent component.

In some embodiments, the consolidating agent emulsions of the presentinvention may comprise a liquid hardenable resin component emulsified ina liquid hardening agent component, wherein the liquid hardenable resincomponent is the internal phase of the emulsion and the liquid hardeningagent component is the external phase of the emulsion. In otherembodiments, the liquid hardenable resin component may be emulsified inwater and the liquid hardening agent component may be present in thewater. In other embodiments, the liquid hardenable resin component maybe emulsified in water and the liquid hardening agent component may beprovided separately. Similarly, in other embodiments, both the liquidhardenable resin component and the liquid hardening agent component mayboth be emulsified in water.

The optional silane coupling agent may be used, among other things, toact as a mediator to help bond the resin to formation particulates orproppant particulates. Examples of suitable silane coupling agentsinclude, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane,3-glycidoxypropyltrimethoxysilane, and combinations thereof. The silanecoupling agent may be included in the liquid hardening agent componentin an amount capable of sufficiently bonding the resin to theparticulate. In some embodiments of the present invention, the silanecoupling agent used is included in the liquid hardening agent componentin the range of about 0.1% to about 3% by weight of the liquid hardeningagent component.

Any surfactant compatible with the hardening agent and capable offacilitating the coating of the resin onto particulates in thesubterranean formation may be used in the liquid hardening agentcomponent. Such surfactants include, but are not limited to, an alkylphosphonate surfactant (e.g., a C₁₂-C₂₂ alkyl phosphonate surfactant),an ethoxylated nonyl phenol phosphate ester, one or more cationicsurfactants, and one or more nonionic surfactants. Mixtures of one ormore cationic and nonionic surfactants also may be suitable. Examples ofsuch surfactant mixtures are described in U.S. Pat. No. 6,311,773 issuedto Todd et al. on Nov. 6, 2001, the relevant disclosure of which isincorporated herein by reference. The surfactant or surfactants that maybe used are included in the liquid hardening agent component in anamount in the range of about 1% to about 10% by weight of the liquidhardening agent component.

While not required, examples of hydrolyzable esters that may be used inthe liquid hardening agent component include, but are not limited to, amixture of dimethylglutarate, dimethyladipate, and dimethylsuccinate;dimethylthiolate; methyl salicylate; dimethyl salicylate;dimethylsuccinate; and combinations thereof. When used, a hydrolyzableester is included in the liquid hardening agent component in an amountin the range of about 0.1% to about 3% by weight of the liquid hardeningagent component. In some embodiments a hydrolyzable ester is included inthe liquid hardening agent component in an amount in the range of about1% to about 2.5% by weight of the liquid hardening agent component.

Use of a diluent or liquid carrier fluid in the liquid hardening agentcomponent is optional and may be used to reduce the viscosity of theliquid hardening agent component for ease of handling, mixing andtransferring. As previously stated, it may be desirable in someembodiments to not use such a solvent for environmental or safetyreasons. Any suitable carrier fluid that is compatible with the liquidhardening agent component and achieves the desired viscosity effects issuitable for use in the present invention. Some suitable liquid carrierfluids are those having high flash points (e.g., about 125° F.) becauseof, among other things, environmental and safety concerns; such solventsinclude, but are not limited to, butyl lactate, butylglycidyl ether,dipropylene glycol methyl ether, dipropylene glycol dimethyl ether,dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butylether, diethyleneglycol butyl ether, propylene carbonate, methanol,butyl alcohol, d'limonene, fatty acid methyl esters, and combinationsthereof. Other suitable liquid carrier fluids include aqueousdissolvable solvents such as, for example, methanol, isopropanol,butanol, glycol ether solvents, and combinations thereof. Suitableglycol ether liquid carrier fluids include, but are not limited to,diethylene glycol methyl ether, dipropylene glycol methyl ether,2-butoxy ethanol, ethers of a C₂ to C₆ dihydric alkanol having at leastone C₁ to C₆ alkyl group, mono ethers of dihydric alkanols,methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof.Selection of an appropriate liquid carrier fluid is dependent on, interalia, the resin composition chosen.

Other resins suitable for use in the present invention are furan-basedresins. Suitable furan-based resins include, but are not limited to,furfuryl alcohol resins, furfural resins, mixtures furfuryl alcoholresins and aldehydes, and a mixture of furan resins and phenolic resins.Of these, furfuryl alcohol resins may be preferred. A furan-based resinmay be combined with a solvent to control viscosity if desired. Suitablesolvents for use in the furan-based consolidation fluids of the presentinvention include, but are not limited to 2-butoxy ethanol, butyllactate, butyl acetate, tetrahydrofurfuryl methacrylate,tetrahydrofurfuryl acrylate, esters of oxalic, maleic and succinicacids, and furfuryl acetate. Of these, 2-butoxy ethanol is preferred. Insome embodiments, the furan-based resins suitable for use in the presentinvention may be capable of enduring temperatures well in excess of 350°F. without degrading. In some embodiments, the furan-based resinssuitable for use in the present invention are capable of enduringtemperatures up to about 700° F. without degrading.

Optionally, the furan-based resins suitable for use in the presentinvention may further comprise a curing agent, inter alia, to facilitateor accelerate curing of the furan-based resin at lower temperatures. Thepresence of a curing agent may be particularly useful in embodimentswhere the furan-based resin may be placed within subterranean formationshaving temperatures below about 350° F. Examples of suitable curingagents include, but are not limited to, organic or inorganic acids, suchas, inter alia, maleic acid, fumaric acid, sodium bisulfate,hydrochloric acid, hydrofluoric acid, acetic acid, formic acid,phosphoric acid, sulfonic acid, alkyl benzene sulfonic acids such astoluene sulfonic acid and dodecyl benzene sulfonic acid (“DDBSA”), andcombinations thereof. In those embodiments where a curing agent is notused, the furan-based resin may cure autocatalytically.

Still other resins suitable for use in the methods of the presentinvention are phenolic-based resins. Suitable phenolic-based resinsinclude, but are not limited to, terpolymers of phenol, phenolicformaldehyde resins, and a mixture of phenolic and furan resins. In someembodiments, a mixture of phenolic and furan resins may be preferred. Aphenolic-based resin may be combined with a solvent to control viscosityif desired. Suitable solvents for use in the present invention include,but are not limited to butyl acetate, butyl lactate, furfuryl acetate,and 2-butoxy ethanol. Of these, 2-butoxy ethanol may be preferred insome embodiments.

Yet another resin-type material suitable for use in the methods of thepresent invention is a phenol/phenol formaldehyde/furfuryl alcohol resincomprising of about 5% to about 30% phenol, of about 40% to about 70%phenol formaldehyde, of about 10% to about 40% furfuryl alcohol, ofabout 0.1% to about 3% of a silane coupling agent, and of about 1% toabout 15% of a surfactant. In the phenol/phenol formaldehyde/furfurylalcohol resins suitable for use in the methods of the present invention,suitable silane coupling agents include, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and3-glycidoxypropyltrimethoxysilane. Suitable surfactants include, but arenot limited to, an ethoxylated nonyl phenol phosphate ester, mixtures ofone or more cationic surfactants, and one or more non-ionic surfactantsand an alkyl phosphonate surfactant.

In some embodiments, resins suitable for use in the consolidating agentemulsion compositions of the present invention may optionally comprisefiller particles. Suitable filler particles may include any particlethat does not adversely react with the other components used inaccordance with this invention or with the subterranean formation.Examples of suitable filler particles include silica, glass, clay,alumina, fumed silica, carbon black, graphite, mica, meta-silicate,calcium silicate, calcine, kaoline, talc, zirconia, titanium dioxide,fly ash, boron, and combinations thereof. In some embodiments, thefiller particles may range in size of about 0.01 μM to about 100 μm. Aswill be understood by one skilled in the art, particles of smalleraverage size may be particularly useful in situations where it isdesirable to obtain high proppant pack permeability (i.e.,conductivity), and/or high consolidation strength. In certainembodiments, the filler particles may be included in the resincomposition in an amount of about 0.1% to about 70% by weight of theresin composition. In other embodiments, the filler particles may beincluded in the resin composition in an amount of about 0.5% to about40% by weight of the resin composition. In some embodiments, the fillerparticles may be included in the resin composition in an amount of about1% to about 10% by weight of the resin composition. Some examples ofsuitable resin compositions comprising filler particles are described inU.S. Ser. No. 11/482,601 issued to Rickman, et al., the relevantdisclosure of which is herein incorporated by reference.

2. Examples of Suitable Emulsifying Agents

As previously stated, the consolidating agent emulsions of the presentinvention comprise an emulsifying agent. Examples of suitableemulsifying agents may include surfactants, proteins, hydrolyzedproteins, lipids, glycolipids, and nanosized particulates, including,but not limited to fumed silica.

Surfactants suitable for use in the present invention are those capableof emulsifying an organic based component in an aqueous based componentso that the emulsion has an aqueous external phase and an organicinternal phase. In some embodiments, the surfactant may comprise anamine surfactant. Such preferred amine surfactants include, but are notlimited to, amine ethoxylates and amine ethoxylated quaternary saltssuch as tallow diamine and tallow triamine exthoxylates and quaternarysalts. Examples of suitable surfactants are ethoxylated C₁₂-C₂₂ diamine,ethoxylated C₁₂-C₂₂ triamine, ethoxylated C₁₂-C₂₂ tetraamine,ethoxylated C₁₂-C₂₂ diamine methylchloride quat, ethoxylated C₁₂-C₂₂triamine methylchloride quat, ethoxylated C₁₂-C₂₂ tetraaminemethylchloride quat, ethoxylated C₁₂-C₂₂ diamine reacted with sodiumchloroacetate, ethoxylated C₁₂-C₂₂ triamine reacted with sodiumchloroacetate, ethoxylated C₁₂-C₂₂ tetraamine reacted with sodiumchloroacetate, ethoxylated C₁₂-C₂₂ diamine acetate salt, ethoxylatedC₁₂-C₂₂ diamine hydrochloric acid salt, ethoxylated C₁₂-C₂₂ diamineglycolic acid salt, ethoxylated C₁₂-C₂₂ diamine DDBSA salt, ethoxylatedC₁₂-C₂₂ triamine acetate salt, ethoxylated C₁₂-C₂₂ triamine hydrochloricacid salt, ethoxylated C₁₂-C₂₂ triamine glycolic acid salt, ethoxylatedC₁₂-C₂₂ triamine DDBSA salt, ethoxylated C₁₂-C₂₂ tetraamine acetatesalt, ethoxylated C₁₂-C₂₂ tetraamine hydrochloric acid salt, ethoxylatedC₁₂-C₂₂ tetraamine glycolic acid salt, ethoxylated C₁₂-C₂₂ tetraamineDDBSA salt, pentamethylated C₁₂-C₂₂ diamine quat, heptamethylatedC₁₂-C₂₂ diamine quat, nonamethylated C₁₂-C₂₂ diamine quat, andcombinations thereof.

In some embodiments of the present invention, a suitable aminesurfactant may have the general formula:

wherein R is a C₁₂-C₂₂ aliphatic hydrocarbon; R′ is independentlyselected from hydrogen or C₁ to C₃ alkyl group; A is independentlyselected from NH or O, and x+y has a value greater than or equal to onebut also less than or equal to three. Preferably the R group is anon-cyclic aliphatic. In some embodiments, the R group contains at leastone degree of unsaturation, i.e., at least one carbon-carbon doublebond. In other embodiments, the R group may be a commercially recognizedmixture of aliphatic hydrocarbons such as soya, which is a mixture ofC₁₄ to C₂₀ hydrocarbons, or tallow which is a mixture of C₁₆ to C₂₀aliphatic hydrocarbons, or tall oil which is a mixture of C₁₄ to C₁₈aliphatic hydrocarbons. In other embodiments, one in which the A groupis NH, the value of x+y is preferably two, with x having a preferredvalue of one. In other embodiments, in which the A group is O, thepreferred value of x+y is two, with the value of x being preferably one.One example of a commercially available amine surfactant is TER 2168Series available from Champion Chemicals located in Fresno, Tex. Othercommercially available examples include ETHOMEEN T/12, a diethoxylatedtallow amine; ETHOMEEN S/12, a diethoxylated soya amine; DUOMEEN O, aN-oleyl-1,3-diaminopropane; DUOMEEN T, a N-tallow-1,3-diaminopropane;all of which are commercially available from Akzo Nobel.

In other embodiments, the surfactant may be a tertiary alkyl amineethoxylate (a cationic surfactant). TRITON RW-100 surfactant (x+y=10moles of ethylene oxide) and TRITON RW-150 surfactant (x+y=15 moles ofethylene oxide) are examples of tertiary alkyl amine ethoxylates thatare commercially available from Dow Chemical Company.

In other embodiments, the surfactant may be a combination of anamphoteric surfactant and an anionic surfactant. In some embodiments,the relative amounts of the amphoteric surfactant and the anionicsurfactant in the surfactant mixture may be of about 30% to about 45% byweight of the surfactant mixture and of about 55% to about 70% by weightof the surfactant mixture, respectively. The amphoteric surfactant maybe lauryl amine oxide, a mixture of lauryl amine oxide and myristylamine oxide (i.e., a lauryl/myristyl amine oxide), cocoamine oxide,lauryl betaine, oleyl betaine, or combinations thereof, with thelauryl/myristyl amine oxide being preferred. The cationic surfactant maybe cocoalkyltriethyl ammonium chloride, hexadecyltrimethyl ammoniumchloride, or combinations thereof, with a 50/50 mixture by weight of thecocoalkyltriethyl ammonium chloride and the hexadecyltrimethyl ammoniumchloride being preferred.

In other embodiments, the surfactant may be a nonionic surfactant.Examples of suitable nonionic surfactants include, but are not limitedto, alcohol oxylalkylates, alkyl phenol oxylalkylates, nonionic esters,such as sorbitan esters, and alkoxylates of sorbitan esters. Examples ofsuitable surfactants include, but are not limited to, castor oilalkoxylates, fatty acid alkoxylates, lauryl alcohol alkoxylates,nonylphenol alkoxylates, octylphenol alkoxylates, tridecyl alcoholalkoxylates, such as polyoxyethylene (“POE”)-10 nonylphenol ethoxylate,POE-100 nonylphenol ethoxylate, POE-12 nonylphenol ethoxylate, POE-12octylphenol ethoxylate, POE-12 tridecyl alcohol ethoxylate, POE-14nonylphenol ethoxylate, POE-15 nonylphenol ethoxylate, POE-18 tridecylalcohol ethoxylate, POE-20 nonylphenol ethoxylate, POE-20 oleyl alcoholethoxylate, POE-20 stearic acid ethoxylate, POE-3 tridecyl alcoholethoxylate, POE-30 nonylphenol ethoxylate, POE-30 octylphenolethoxylate, POE-34 nonylphenol ethoxylate, POE-4 nonylphenol ethoxylate,POE-40 castor oil ethoxylate, POE-40 nonylphenol ethoxylate, POE-40octylphenol ethoxylate, POE-50 nonylphenol ethoxylate, POE-50 tridecylalcohol ethoxylate, POE-6 nonylphenol ethoxylate, POE-6 tridecyl alcoholethoxylate, POE-8 nonylphenol ethoxylate, POE-9 octylphenol ethoxylate,mannide monooleate, sorbitan isostearate, sorbitan laurate, sorbitanmonoisostearate, sorbitan monolaurate, sorbitan monooleate, sorbitanmonopalmitate, sorbitan monostearate, sorbitan oleate, sorbitanpalmitate, sorbitan sesquioleate, sorbitan stearate, sorbitan trioleate,sorbitan tristearate, POE-20 sorbitan monoisostearate ethoxylate, POE-20sorbitan monolaurate ethoxylate, POE-20 sorbitan monooleate ethoxylate,POE-20 sorbitan monopalmitate ethoxylate, POE-20 sorbitan monostearateethoxylate, POE-20 sorbitan trioleate ethoxylate, POE-20 sorbitantristearate ethoxylate, POE-30 sorbitan tetraoleate ethoxylate, POE-40sorbitan tetraoleate ethoxylate, POE-6 sorbitan hexastearate ethoxylate,POE-6 sorbitan monstearate ethoxylate, POE-6 sorbitan tetraoleateethoxylate, and/or POE-60 sorbitan tetrastearate ethoxylate. Preferrednonionic surfactants include alcohol oxyalkyalates such as POE-23 laurylalcohol and alkyl phenol ethoxylates such as POE (20) nonyl phenylether.

While cationic, amphoteric, and nonionic surfactants are preferred, anysuitable emulsifying surfactant may be used. Good surfactants foremulsification typically need to be either ionic, to give chargestabilization, to have a sufficient hydrocarbon chain length or cause atighter packing of the hydrophobic groups at the oil/water interface toincrease the stability of the emulsion. One of ordinary skill in the artwith the benefit of this disclosure will be able to select a suitablesurfactant depending upon the consolidating agent that is beingemulsified. Additional suitable surfactants may include other cationicsurfactants and even anionic surfactants. Examples include, but are notlimited to, hexahydro-1 3,5-tris(2-hydroxyethyl)triazine, alkyl etherphosphate, ammonium lauryl sulfate, ammonium nonylphenol ethoxylatesulfate, branched isopropyl amine dodecylbenzene sulfonate, branchedsodium dodecylbenzene sulfonate, dodecylbenzene sulfonic acid, brancheddodecylbenzene sulfonic acid, fatty acid sulfonate potassium salt,phosphate esters, POE-1 ammonium lauryl ether sulfate, OE-1 sodiumlauryl ether sulfate, POE-10 nonylphenol ethoxylate phosphate ester,POE-12 ammonium lauryl ether sulfate, POE-12 linear phosphate ester,POE-12 sodium lauryl ether sulfate, POE-12 tridecyl alcohol phosphateester, POE-2 ammonium lauryl ether sulfate, POE-2 sodium lauryl ethersulfate, POE-3 ammonium lauryl ether sulfate, POE-3 disodium alkyl ethersulfosuccinate, POE-3 linear phosphate ester, POE-3 sodium lauryl ethersulfate, POE-3 sodium octylphenol ethoxylate sulfate, POE-3 sodiumtridecyl ether sulfate, POE-3 tridecyl alcohol phosphate ester, POE-30ammonium lauryl ether sulfate, POE-30 sodium lauryl ether sulfate, POE-4ammonium lauryl ether sulfate, POE-4 ammonium nonylphenol ethoxylatesulfate, POE-4 nonyl phenol ether sulfate, POE-4 nonylphenol ethoxylatephosphate ester, POE-4 sodium lauryl ether sulfate, POE-4 sodiumnonylphenol ethoxylate sulfate, POE-4 sodium tridecyl ether sulfate,POE-50 sodium lauryl ether sulfate, POE-6 disodium alkyl ethersulfosuccinate, POE-6 nonylphenol ethoxylate phosphate ester, POE-6tridecyl alcohol phosphate ester, POE-7 linear phosphate ester, POE-8nonylphenol ethoxylate phosphate ester, potassium dodecylbenzenesulfonate, sodium 2-ethyl hexyl sulfate, sodium alkyl ether sulfate,sodium alkyl sulfate, sodium alpha olefin sulfonate, sodium decylsulfate, sodium dodecylbenzene sulfonate, sodium lauryl sulfate, sodiumlauryl sulfoacetate, sodium nonylphenol ethoxylate sulfate, and/orsodium octyl sulfate.

Other suitable emulsifying agents are described in U.S. Pat. Nos.6,653,436 and 6,956,086 both issued to Back, et al., the relevantdisclosures of which are herein incorporated by reference.

In some embodiments, the emulsifying agent may function in more than onecapacity. For example, in some embodiments, a suitable emulsifying agentmay also be a hardening agent. Examples of suitable emulsifying agentsthat may also function as a hardening agent include, but are not limitedto, those described in U.S. Pat. No. 5,874,490, the relevant disclosureof which is herein incorporated by reference.

In some embodiments, the emulsifying agent may be present in theconsolidating agent emulsion in an amount in the range of about 0.001%to about 10% by weight of the consolidating agent emulsion composition.In some embodiments, the emulsifying agent may be present in theconsolidating agent emulsion in an amount in the range of about 0.05% toabout 5% by weight of the consolidating agent emulsion composition.

3. Examples of Optional Additives

Optionally, the consolidating agent emulsions of the present inventionmay comprise additional additives such as emulsion stabilizers, emulsiondestabilizers, antifreeze agents, biocides, algaecides, pH controladditives, oxygen scavengers, clay stabilizers, and the like or anyother additive that does not adversely affect the consolidating agentemulsion compositions. For instance, an emulsion stabilizer may bebeneficial when stability of the emulsion is desired for a lengthenedperiod of time or at specified temperatures. In some embodiments, theemulsion stabilizer may be substantially any acid. In some embodiments,the emulsion stabilizer may be an organic acid, such as acetic acid. Insome embodiments, the emulsion stabilizer may be a plurality ofnanoparticulates. If an emulsion stabilizer is utilized, it ispreferably present in an amount necessary to stabilize the consolidatingagent emulsion composition. An emulsion destabilizer may be beneficialwhen stability of the emulsion is not desired. The emulsion destabilizermay be, inter alia, an alcohol, a pH additive, a surfactant or an oil.If an emulsion destabilizer is utilized, it is preferably present in anamount necessary to break the emulsion. Additionally, antifreeze agentsmay be beneficial to improve the freezing point of the emulsion. In someembodiments, optional additives may be included in the consolidatingagent emulsion in an amount in the range of about 0.001% to about 10% byweight of the consolidating agent emulsion composition. One of ordinaryskill in the art with the benefit of this disclosure will recognize thatthe compatibility of any given additive should be tested to ensure thatit does not adversely affect the performance of the consolidating agentemulsion.

In some embodiments, the consolidating agent emulsions of the presentinvention may further comprise a foaming agent. As used herein, the term“foamed” also refers to co-mingled fluids. In certain embodiments, itmay desirable that the consolidating agent emulsion is foamed to, interalia, provide enhanced placement of a consolidating agent emulsioncomposition and/or to reduce the amount of aqueous fluid that isrequired, e.g., in water sensitive subterranean formations. Variousgases can be utilized for foaming the consolidating agent emulsions ofthis invention, including, but not limited to, nitrogen, carbon dioxide,air, methane, and mixtures thereof. One of ordinary skill in the artwith the benefit of this disclosure will be able to select anappropriate gas that may be utilized for foaming the consolidating agentemulsions of the present invention. In some embodiments, the gas may bepresent in a consolidating agent emulsion of the present invention in anamount in the range of about 5% to about 98% by volume of theconsolidating agent emulsion. In some embodiments, the gas may bepresent in a consolidating agent emulsion of the present invention in anamount in the range of about 20% to about 80% by volume of theconsolidating agent emulsion. In some embodiments, the gas may bepresent in a consolidating agent emulsion of the present invention in anamount in the range of about 30% to about 70% by volume of theconsolidating agent emulsion. The amount of gas to incorporate into theconsolidating agent emulsion may be affected by factors including theviscosity of the consolidating agent emulsion and wellhead pressuresinvolved in a particular application.

In those embodiments where it is desirable to foam the consolidatingagent emulsions of the present invention, surfactants such asHY-CLEAN(HC-2)™ surface-active suspending agent, PEN-5, or AQF-2™additive, all of which are commercially available from HalliburtonEnergy Services, Inc., of Duncan, Okla., may be used. Additionalexamples of foaming agents that may be utilized to foam and stabilizethe consolidating agent emulsions may include, but are not limited to,betaines, amine oxides, methyl ester sulfonates, alkylamidobetaines suchas cocoamidopropyl betaine, alpha-olefin sulfonate,trimethyltallowammonium chloride, C₈ to C₂₂ alkylethoxylate sulfate andtrimethylcocoammonium chloride. Other suitable foaming agents and foamstabilizing agents may be included as well, which will be known to thoseskilled in the art with the benefit of this disclosure.

Other additives may be suitable as well as might be recognized by oneskilled in the art with the benefit of this disclosure.

B. Examples of Some Suitable Methods of the Present Invention

The consolidating agent emulsions of the present invention may be usedin any suitable subterranean operation in which it is desirable tocontrol particulate migration and/or modify the stress-activatedreactivity of subterranean fracture faces and other surfaces insubterranean formations. Additionally, when used in conjunction with awell bore, these methods can be performed at any time during the life ofthe well.

One example of a method of the present invention comprises: providing aconsolidating agent emulsion that comprises an aqueous fluid, anemulsifying agent, and a consolidating agent; and treating at least aplurality of particulates with the consolidating agent emulsion toproduce a plurality of consolidating agent coated particulates. In someembodiments, these consolidating agent coated particulates may then beused downhole, for example, in a fracturing or a gravel packingoperation. The term “coated particulate” as used herein meansparticulates that have been at least partially coated with a processcomprising a consolidating agent emulsion of the present invention. Theparticulates may be coated by any suitable method as recognized by oneskilled in the art with the benefit of this disclosure. The term“coated” does not imply any particular degree of coverage of theparticulates with a consolidating agent.

In other embodiments, the present invention provides a method comprisingproviding a treatment fluid that comprises a consolidating agentemulsion that comprises an aqueous fluid, an emulsifying agent, and aconsolidating agent; and introducing the treatment fluid into asubterranean formation. In some embodiments, the consolidating agentemulsion may then control particulate migration by allowing theconsolidating agent to at least partially coat or otherwise becomeincorporated with the formation surface (note that no specific depth oftreatment is implied), and consolidate at least some particulates in aportion of a subterranean formation.

In other embodiments, the present invention provides a method comprisingproviding a treatment fluid that comprises at least a plurality ofparticulates coated using a consolidating agent emulsion that comprisesan aqueous fluid, an emulsifying agent, and a consolidating agent;introducing the treatment fluid into a subterranean formation; andallowing the consolidating agent to interact with at least a portion ofa mineral surface to modify the stress-activated reactivity of at leasta portion of a mineral surface in the subterranean formation.

In some embodiments, the consolidating agent emulsions of the presentinvention may be used, inter alia, in primary, remedial, or proactivemethods. Whether a particular method of this invention is “primary,”“remedial,” or “proactive” is determined relative to the timing of afracturing treatment or a gravel packing treatment. In some embodiments,a primary method of the present invention may involve using theconsolidating agent emulsions of the present invention in conjunctionwith a fracturing fluid or a gravel pack fluid (e.g., as a component ofthe fracturing fluid or a gravel pack fluid so that the consolidatingagent emulsions of the present invention are introduced into thesubterranean formation with the fluid). The remedial methods may be usedin wells wherein a portion of the well has previously been fracturedand/or propped. The remedial methods also may be used in a gravelpacking situation, for example where there has been a screen problem orfailure. The proactive methods may be used in wells that have not yetbeen fractured or gravel packed. In some embodiments, the proactivemethods can be performed in conjunction with a fracturing treatment, forexample, as a pre-pad to the fracturing treatment or in any diagnosticpumping stage performed before a fracturing, gravel packing, oracidizing procedure.

One of ordinary skill in the art will recognize that the presentinvention may be useful to stabilize other types of particulates, suchas the coatings (also referred to as “grapeskin”) left over from someencapsulated materials.

In some embodiments, it may be desirable to utilize a preflush solutionprior to the placement of the consolidating agent emulsion compositionsin a subterranean formation, inter alia, to remove excess fluids fromthe pore spaces in the subterranean formation, to clean the subterraneanformation, etc. Examples of suitable preflush solutions include, but arenot limited to, aqueous fluids, solvents, and surfactants capable ofaltering the wetability of the formation surface. Examples of suitablepreflush solvents may include mutual solvents such as MUSOL andN-VER-SPERSE A, both commercially available from Halliburton EnergyServices, Inc., of Duncan, Okla. An example of a suitable preflushsurfactant may also include an ethoxylated nonylphenol phosphate estersuch as ES-5, which μs commercially available from Halliburton EnergyServices, Inc., of Duncan, Okla. Additionally, in those embodimentswhere the consolidating agent emulsions of the present inventioncomprise a resin composition, it may be desirable to include a hardeningagent in a preflush solution.

Additionally, in some embodiments, it may be desirable to utilize apostflush solution subsequent to the placement of the consolidatingagent emulsion compositions in a subterranean formation, inter alia, todisplace excess resin from the near well bore region. Examples ofsuitable postflush solutions include, but are not limited to, aqueousfluids, solvents, gases, e.g. nitrogen, or any combination thereof.Additionally, in some embodiments, in may be desirable to include ahardening agent in the postflush solution. For example, certain types ofresin compositions including, but not limited to, furan based resins,urethane resins, and epoxy based resins, may be catalyzed with ahardening agent placed in a postflush solution.

Below are some additional, but not exclusive, examples of some of theprimary, remedial, and proactive methods of the present invention.

1. Primary Methods

In some embodiments, the consolidating agent emulsions of the presentinvention may be used in a primary method with a well treatment fluid,such as a fracturing fluid or a gravel pack fluid. One example of such amethod comprises: providing a fracturing fluid that comprises aconsolidating agent emulsion comprising an aqueous fluid, an emulsifyingagent, and a consolidating agent; placing the fracturing fluid into asubterranean formation at a pressure sufficient to create or enhance afracture therein; and allowing the consolidating agent to at leastpartially consolidate particulates within a portion of the subterraneanformation. The fracturing fluids in these primary embodiments maycomprise any suitable component usually found in fracturing fluids inview of the characteristics of the formation including, but not limitedto, an aqueous base fluid, proppant particulates, gelling agents,surfactants, breakers, buffers, a gas phase (if the fracturing fluid isfoamed or commingled), coupling agents, and the like. One of ordinaryskill in the art with the benefit of this disclosure will likelyrecognize the appropriate components in conjunction with a consolidatingagent emulsion composition of the present invention for use in afracturing fluid for a given application.

One example of a primary gravel pack method of the present inventioncomprises: providing a gravel pack fluid that comprises gravel and aconsolidating agent emulsion composition, the consolidating agentemulsion composition comprising an aqueous fluid, an emulsifying agent,and a consolidating agent; contacting a portion of the subterraneanformation with the gravel pack fluid so as to place a gravel pack in ornear a portion of the subterranean formation; and allowing theconsolidating agent to stabilize particulates within the subterraneanformation. The gravel pack fluids used in these embodiments may be anysuitable gravel pack fluid, and it may comprise those things usuallyfound in gravel pack fluids including, but not limited to, an aqueousbase fluid, gravel particulates, gelling agents, surfactants, breakers,buffers, a gas phase (if the fluid is foamed or commingled), and thelike. One of ordinary skill in the art with the benefit of thisdisclosure will likely recognize the appropriate components inconjunction with a consolidating agent emulsion composition of thepresent invention for use in a gravel pack fluid for a givenapplication.

2. Remedial Measures

In some remedial embodiments of the present invention, after afracturing treatment or a gravel pack treatment has been performed, theconsolidating agent emulsions of the present invention may be introducedinto an unconsolidated zone of a subterranean formation to stabilizeparticulates within the zone. The consolidating agent emulsions maydisperse any loose fines within a proppant pack in a fracture, move anyfines away from the fracture (or near well bore), stabilize gravelparticulates around a screen, stabilize a screen failure, and/or lockthe fines in the formation.

In another remedial embodiment, the consolidating agent emulsions of thepresent invention may be introduced into a subterranean formation thatis producing unconsolidated particulate material as a result of, interalia, depletion, water breakthrough, etc. The consolidating agentemulsions may stabilize and/or strengthen the particulates in theformation and thereby reduce their undesirable production.

3. The Proactive Methods

The proactive methods of the present invention are most suited for wellsthat have not been fractured or gravel packed yet. These methods can beused as a pre-treatment before a fracturing treatment or at the earlystage of a fracturing treatment (including diagnostic pumping) as apre-pad treatment.

In some proactive embodiments of the present invention, theconsolidating agent emulsions of the present invention may be introducedinto an unconsolidated zone of a subterranean formation to stabilizeparticulates within the zone.

In some embodiments, the proactive methods of the present inventioncomprise placing the consolidating agent emulsions before or as part ofa pre-pad of a fracturing treatment into a subterranean formation. Insome embodiments, subsequent to placing the consolidating agent emulsioncomposition in the formation, the subterranean formation may befractured. This fracturing step may include the introduction of aplurality of particulates into the formation. In some embodiments, atleast a portion of the particulates may be coated with a consolidatingagent. In some embodiments, the coated particulates may be introducedinto the fluid at the end of the fracturing treatment. In someembodiments, at least a plurality of the particulates may be of a largersize, such that the fracture has a higher conductivity. For example, thesize of at least a plurality of the particulates may have a weight meanparticle size (“d50”) of about 20 times to about 50 times the d50 of theformation particulates.

In some embodiments, the consolidating agent emulsions of the presentinvention may be used in a supported open hole well bore. In supportedopen hole well bores, a slotted liner or screen, for example, may beutilized to provide mechanical support and/or to allow the bore hole toconform and/or comply to the liner in very weak formation layers. Inaddition, in some supported open hole well bores, zonal isolationpackers may also be used. It may be desirable in certain embodiments touse the consolidating agent emulsions of the present invention in asupported open hole well bore. One potential advantage of utilizing theconsolidating agent emulsions of the present invention in a supportedopen hole well bore is that the formation around the well bore may bestabilized, thus mitigating any fines movement or long term plugging,such that the placement of a gravel pack may no longer be necessary.

4. Introducing Coated Particulates

In some embodiments, the consolidating agent emulsions of the presentinvention may be coated on particulates to be used in a fracturing orgravel packing process like those described above. As stated above, theterm “coated” implies no particular degree of coverage or mechanism bywhich the consolidating agent becomes incorporated with theparticulates. The term includes, but is not limited to, simple coating,adhesion, impregnation, etc. The resultant coated particulates may beintroduced as part of a fracturing or gravel packing process, at anypoint during one of the methods described above. Preferably, the coatedparticulates are introduced towards the end of a fracturing or gravelpacking treatment so that the maximum economic benefit can be obtained.

In accordance with the methods and compositions of the presentinvention, all or part of the particulates may be coated (preferablyon-the-fly) with a consolidating agent using the consolidating agentemulsions of the present invention and may then be suspended in afracturing fluid or used as part of a gravel packing process. Theconsolidating agent emulsions are used to coat the consolidating agenton dry particulates while the particulates are conveyed in a conveyingand/or mixing device. The amount of consolidating agent coated on theparticulates is in the range of about 0.1% to about 20% by weight of theparticulate, with about 1-5% being preferred.

The term “on-the-fly” is used herein to mean that a flowing stream iscontinuously introduced into another flowing stream so that the streamsare combined and mixed while continuing to flow as a single stream. Thecoating of the dry particulates with the consolidating agent emulsionsand any mixing of the consolidating agent coated particulates with afracturing fluid or treatment fluid are all preferably accomplishedon-the-fly. However, as is well understood by those skilled in the art,such mixing can also be accomplished by batch mixing or partial batchmixing.

A wide variety of particulate materials may be used in accordance withthe present invention, including, but not limited to, sand, bauxite,ceramic materials, glass materials, resin precoated proppant (e.g.,commercially available from Borden Chemicals and Santrol, for example,both from Houston, Tex.), polymer materials, TEFLON(tetrafluoroethylene) materials, nut shells, ground or crushed nutshells, seed shells, ground or crushed seed shells, fruit pit pieces,ground or crushed fruit pits, processed wood, composite particulatesprepared from a binder with filler particulate including silica,alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide,meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash,hollow glass microspheres, solid glass, and mixtures thereof. Theparticulate material used may have a particle size in the range of about2 to about 400 mesh, U.S. Sieve Series. Preferably, the particulatematerial is graded sand having a particle size in the range of about 10to about 70 mesh, U.S. Sieve Series. Preferred sand particle sizedistribution ranges are one or more of 10-20 mesh, 20-40 mesh, 40-60mesh or 50-70 mesh, depending on the particle size and distribution ofthe formation particulates to be screened out by the particulatematerials. Other particulates that may be suitable for use insubterranean applications also may be useful.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the invention.

Example 1

Diagenesis tests were performed using 3-in. diameter radial APIconductivity cells fitted with Ohio sandstone core wafers on the top andbottom of the proppant pack. Alumina-based proppant at a loading of 2lb/ft² was used for the proppant pack, with 2% KCl as the fluid medium.Sample proppant pack No. 1 contained untreated proppant and Sampleproppant pack No. 2 contained proppant that was coated using theconsolidating agent emulsions of the present invention.

After preparation, each sample was subjected to a stress load of 10,000psi at 250° F. for 126 hours in static conditions. The API conductivitycell was then disassembled, and the Ohio sandstone wafers were examinedto determine proppant particulate embedment by optical microscopy. Foreach sample, the proppant layer next to the Ohio sandstone wafer and thecenter of the proppant pack were examined by Environmental ScanningElectron Microscope. FIG. 1 is a microscopy image of proppantparticulates used in each sample before exposure to the stress load andtemperatures. FIG. 2 is a microscopy image of Sample proppant pack No.1, containing untreated proppant particulates, after being exposed tothe stress load and temperatures. FIG. 3 is a microscopy image of Sampleproppant pack No. 2, containing proppant particulates that were coatedusing the consolidating agent emulsions of the present invention, afterbeing exposed to the stress load and temperatures.

Electron dispersive X-ray (EDX) was also used to determine thesilica-to-aluminum ratio in various areas of Sample proppant pack No. 1.The silica-to-aluminum ratio observed for the proppant was 0.9, as istypical for ceramic proppant, while that for the Ohio sandstone was 8.4.The porosity filling precipitate was found to be 4.9, or an intermediateconcentration of these metals. The silica-to-aluminum ratio was notmeasured in Sample proppant pack No. 2 because the porosity fillingprecipitate was not found in the pack.

Thus, by treating the proppant pack with the consolidating agentemulsions of the present invention, diagenesis appeared to be reducedand the porosity filling precipitate at least appeared to besubstantially eliminated from the pack.

Example 2

Conductivity tests were performed by preparing 5-lb/ft² proppant packsof 20/40-mesh ceramic proppant. Sample proppant pack No. 3 and Sampleproppant pack No. 4 were each separately placed between twounconsolidated silica wafers, which were used to simulate unconsolidatedformation faces of a soft formation. Each sample proppant pack and thetwo unconsolidated silica wafers were then placed between two Ohiosandstone core wafers and placed in a linear API conductivity cell.

The two cells were then brought to an initial stress of 2,000 psi and180° F. Sample proppant pack No. 3 was then treated with only 3% KCl andSample proppant pack No. 4 was treated with a consolidating agentemulsion of the present invention. Both treatments were performed byinjecting the proppant pack with 3 pore volumes of the treatment fluid.Flow was then initiated through each Sample proppant pack in theconventional linear direction to determine the initial conductivity ofeach of the Sample proppant packs at 2,000 psi closure stress. Afterstable flow was achieved, flow at a rate of 2 mL/min was initiatedthrough the wafers to simulate production from the formation into thefracture. The effluent fluid was then captured to examine for finesproduction.

Sample proppant pack No. 3 failed with the continuous flow from thesilica wafers into the proppant pack. This failure resulted in the finesexiting the test cell, thereby causing the overall width to collapse.The collapse was caused by the flow removing the fines that make up thewafer and transporting them through the proppant pack and out of thecell. After the failure of the proppant pack, all flow was stopped forthis test cell. Differential pressure for the conductivity measurementincreased beyond the capacity of the sensor because of the finesinvasion into the pack. Therefore, no subsequent values were obtainedfor Sample proppant pack No. 3.

Sample proppant pack No. 4 continued to allow inflow through the silicawafers without failure or collapse of the overall width. After reachingstable conductivity measurements at 2,000 psi closure, the stress loadwas increased to 4,000 psi closure. Again, after reaching stableconductivity measurements, the stress load was decreased back to 2,000psi closure. This stress cycle was repeated several times with adoubling in inflow rate with each cycle to try to destabilize the pack.

Conductivity results for Sample proppant pack No. 3 and Sample proppantpack No. 4 are shown in Table 1 below.

TABLE 1 Closure Inflow Conductivity (mD-ft) Conductivity (mD-ft) TimeStress Rate for Sample proppant for Sample proppant (hr) (psi) (cc/min)pack No. 3 pack No. 4 0 2000 2 13787 12435 20 2000 2 2 11089 43 2000 2 —11362 67 2000 2 — 12283 95 4000 4 — 11708 139 4000 4 — 11540 164 2000 2— 11822 187 2000 2 — 11905 235 2000 2 — 11504 307 4000 4 — 11166 3322000 2 — 11756 355 2000 2 — 11327

Thus, Example 2 demonstrates, inter alia, that the consolidating agentemulsions of the present invention may effectively control or mitigatethe invasion of formation fines into the proppant and may allow theproppant pack to maintain conductivity.

Example 3

Mechanical strength tests were performed using two Salt Wash South coresamples having a 4 inch diameter with a ¼ inch perforation drilled intothe end of each core. Sample Core No. 1 was untreated. Sample Core No. 2was treated using consolidating agent emulsion “FDP-S 863,” which isavailable from Halliburton Energy Services, Inc., of Duncan, Okla. Theconsolidating agent emulsion was then displaced with a postflushcomprising nitrogen, and then the resin composition in the consolidatingagent emulsion was allowed to cure. Both sample cores were installedinside a 4 inch diameter Hassler Sleeve Assembly. A confining pressureof 1,500 psi was then applied on the core. A brine prepared from 3%(wt/vol) KCl was injected into the cores for testing. For Sample CoreNo. 1, the injection rates were increased while recording the change inpressure and flow rate at which sand was produced. For Sample Core No.2, the test cell limitations were reached without inducing sandproduction. Core plugs were then drilled out of the large cores and theunconfined compressive strength was measured. FIGS. 4 and 5 aremicroscopy images of Sample Core No. 2, demonstrating how theconsolidating agent may be concentrated at contact points betweenparticulates to provide enhanced compressive strength withoutsignificantly damaging reservoir permeability.

Compressive strength results for Sample Core No. 1 and Sample Core No. 2are shown in Table 2 below.

TABLE 2 Sample Core No. 1 (untreated) Sample Core No. 2 (treated) CoreSize 4 inch diameter, 4 inch diameter, 6 inch length 6 inch lengthPerforation ¼ inch ¼ inch Diameter Perforation Length 4 inches 4 inchesConfining Stress 1500 psi 1500 psi initially to 3000 psi at high flowconditions Maximum Flow 300 mL/min, 3000 mL/min, 2000 psi ΔP Conditions300 psi ΔP Sand Produced Yes No Unconfined  400 psi 1332 psi CompressiveStrength Cohesive Strength  10 psi  100 psi

Thus, Example 3 demonstrates, inter alia, that the consolidating agentemulsions of the present invention may provide enhanced compressiveand/or cohesive strength, and may also minimize the flow back ofunconsolidated particulate material.

Example 4

A synthetic sand mixture prepared from 90% (wt/wt) of 70/170-mesh sandand 10% of silica flour was first packed inside a rubber sleeve. Thesand pack was then installed inside a stainless flow cell. An annularpressure of 1,000 psi was then applied on the sand pack. A brineprepared from 3% (wt/vol) KCl was used to saturate the sand pack at aninjection rate of 2 mL/min by flowing from the bottom up direction ofthe flow cell for a total volume of 1,000 mL. After the sand pack wassaturated, the injection flow rate was increased to 10 mL/min until asteady pressure drop was obtained to determine initial permeability forthe sand pack.

For Sample Pack No. 1, the treatment sequence included a pre-flush of 3%KCl brine containing 0.5% of a cationic surfactant with an injectionrate of 10 mL/min for a total volume of 1,000 mL, a treatment of 1.5%active water-based resin mixture with an injection rate of 10 mL/min fora total volume of 1,000 mL, and a post-flush volume of 3% KCl brinecontaining 0.5% of a cationic surfactant with an injection rate of 10mL/min for a total volume of 1,000 mL After the post-flush injection,all the values were shut off. Heat was applied to the flow cell by heattape to bring the temperature to 180° F. and the treated sand pack wasallowed to cure for 48 hours.

For Sample Pack No. 2, the treatment sequence included a pre-flush of 3%KCl brine containing 0.5% of a cationic surfactant with an injectionrate of 10 mL/min for a total volume of 1,000 mL, a treatment of 3%active water-based resin mixture with an injection rate of 10 mL/min fora total volume of 1,000 mL, and a post-flush volume of 3% KCl brinecontaining 0.5% of a cationic surfactant with an injection rate of 10mL/min for a total volume of 1,000 mL After the post-flush injection,all the values were shut off. Heat was applied to the flow cell by heattape to bring the temperature to 180° F. and the treated sand pack wasallowed to cure for 48 hours.

For Sample Pack No. 3, the treatment sequence included a pre-flush of 3%KCl brine containing 0.5% of a cationic surfactant with an injectionrate of 10 mL/min for a total volume of 1,000 mL, a treatment of 3%active water-based resin mixture with an injection rate of 10 mL/min fora total volume of 1,000 mL, and a post-flush volume of 3% KCl brinecontaining 0.5% of a cationic surfactant with an injection rate of 10mL/min for a total volume of 1,000 mL After the post-flush injection,all the values were shut off. Heat was applied to the flow cell by heattape to bring the temperature to 180° F. and the treated sand pack wasallowed to cure for 48 hours.

After the curing period for each Sample Pack, the temperature wasallowed to cool down to room temperature. Again, a brine of 3% KCl wasinjected from the bottom up direction through the treated sand pack todetermine its regained permeability. After this brine injection, therubber sleeve containing the sand pack was removed from the flow cell.An incision was made from the top to the bottom of the sleeve to allowfor the removal of the consolidated sand pack. Cores were then obtainedfrom each of the sample consolidated sand packs to determine mechanicalproperties of the consolidated sand. Compressive strength results andregained permeability results for each sample are shown in FIGS. 6 and7, respectively.

Thus, Example 4 demonstrates, inter alia, that the consolidating agentemulsions of the present invention may provide enhanced compressivestrength and/or cohesive strength, and satisfactory regainedpermeability.

Example 5

Flow tests were conducted on a 7 inch diameter×24 inch long Castlegatecore. In phase one, the core was saturated with a potassium chloride(KCl) brine and then taken to irreducible water saturation by flowingodorless mineral spirits (OMS). The core was then placed in a testassembly under simulated reservoir conditions of 6000 psi over burdenpressure and 3000 psi pore pressure. The core was then perforated using500 psi under balance to allow the perforation to surge and clean upslightly. The core was then removed and placed in a large flow cellwhere 3000 psi confining stress was applied. The core was then flowed atseveral flow rates using OMS and OMS+KCl. During this phase, significantquantities of formation sand were produced.

In phase two, the core was then heated to 170° F. and treated using 1pore volume of a consolidating agent emulsion of the present invention,displaced with nitrogen, and allowed to cure over night. The core wasonce again flowed at several flow rates using OMS and OMS+KCl whilemaintaining 3000 psi confining stress. During this phase only very smallquantities of sand production were observed. The core was removed and CTscanned to examine the perforation. FIG. 8 is a CT scan image from thecore.

The Castlegate core had an unconfined compressive strength of 800 psibefore treatment with a consolidating agent emulsion of the presentinvention and an unconfined compressive strength of 1500 psi aftertreatment with a consolidating agent emulsion. The permeability of thecore was 500 to 1000 millidarcies and the porosity was 25% to 30%.

Flow tests results for phases 1 and 2 are shown in Table 3 below.

TABLE 3 Phase One Phase Two Max Flow Rate 1.796 gallons per Max FlowRate 1.969 gpm (OMS minute (“gpm) (OMS and OMS + and OMS + KCl) KCl) MaxΔP - 592 psi Max ΔP - 723 psi Total sand produced - 353 gr Total sandproduced - 16.4 gr  0.7 gpm (OMS) - 70 gr sand 0.45 gpm (OMS) - 2.6 grsand 0.75 gpm(OMS) - 22 gr sand  0.8 gpm (OMS) - 3.9 gr sand  0.9gpm(OMS) - 61 gr sand 1.25 gpm (OMS + KCl) 0.74 gr sand 0.95 gpm (OMS +KCl) 160 gr 1.65 gpm (OMS + KCl) 1.65 gr sand sand 1.55 gpm (OMS + KCl)40 gr sand 1.97 gpm (OMS + KCl) 1.69 gr sand

Thus, Example 5 demonstrates, inter alia, that the consolidating agentemulsions of the present invention may provide enhanced compressiveand/or cohesive strength.

Example 6

Flow tests were conducted on a 7 inch diameter×24 inch long Castlegatecore. The core was perforated using 504 psi under balance. The core washeated to 170° F. and treated using 2 pore volumes of a consolidatingagent emulsion of the present invention, displaced with nitrogen, andallowed to cure over night. The core was flowed at a maximum rate of1.788 gpm using OMS and OMS+a 3% KCl brine while maintaining 3000 psiconfining stress. During this phase only very small quantities of sandproduction were observed. The core was removed and CT scanned to examinethe perforation. FIG. 9 is a CT scan image from the core. Flow testsresults are shown in Table 4 below.

TABLE 4 Delta Fluid Pressure (psi) Flow Rate (gpm) Sand Produced (gr)OMS 191 0.346 3.6 OMS 620 1.672 1.4 OMS + KCl 551 1.01 0 OMS + KCl 7720.859 0

Thus, Example 6 demonstrates, inter alia, that the consolidating agentemulsions of the present invention may provide enhanced compressiveand/or cohesive strength.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. In particular, every range of values(of the form, “of about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values, and set forthevery range encompassed within the broader range of values. Also, theterms in the claims have their plain, ordinary meaning unless otherwiseexplicitly and clearly defined by the patentee. Moreover, the indefinitearticles “a” or “an”, as used in the claims, are defined herein to meanone or more than one of the element that it introduces.

1-30. (canceled)
 31. A consolidation fluid comprising: an aqueous basefluid comprising a hardening agent; an emulsified resin having anaqueous external phase and an organic internal phase; a silane couplingagent; and a surfactant.
 32. The consolidation fluid of claim 31 whereinthe emulsified resin is selected from the group consisting ofepoxy-based resins, novolak resins, polyepoxide resins, phenol-aldehyderesins, urea-aldehyde resins, urethane resins, phenolic resins, furanresins, furan/furfuryl alcohol resins, phenolic/latex resins, phenolformaldehyde resins, polyester resins, urethane resins, and mixturesthereof.
 33. The consolidation fluid of claim 31 wherein the silanecoupling agent is selected from the group consisting ofN-2-(aminoethyl)-3-aminopropyl trimethoxysilane,3-glycidoxypropyltrimethoxysilane, and mixtures thereof.
 34. Theconsolidation fluid of claim 31 wherein the surfactant is selected fromthe group consisting of an alkyl phosphonate surfactant, an ethoxylatednonyl phenol phosphonate ester, a cationic surfactant, a nonionicsurfactant, and mixtures thereof.
 35. The consolidation fluid of claim31 wherein the consolidation fluid is foamed.
 36. The consolidationfluid of claim 31 further comprising an emulsifying agent selected fromthe group consisting of surfactants, proteins, hydrolyzed proteins,lipids, glycolipids, nano-sized particulates, and fumed silica is usedto emulsify the resin.
 37. The consolidation fluid of claim 31 whereinthe surfactant is a mixture of an amphoteric surfactant present in anamount from about 30% to about 45% by weight of the surfactant mixtureand an anionic surfactant in an amount from about 55% to about 70% byweight of the surfactant mixture.
 38. An emulsified consolidation fluidcomprising: an aqueous base fluid comprising a hardening agent; anemulsified resin having an aqueous external phase and an organicinternal phase; a silane coupling agent; an emulsifying agent; and, asurfactant.
 39. The consolidation fluid of claim 38 wherein theemulsified resin is selected from the group consisting of epoxy-basedresins, novolak resins, polyepoxide resins, phenol-aldehyde resins,urea-aldehyde resins, urethane resins, phenolic resins, furan resins,furan/furfuryl alcohol resins, phenolic/latex resins, phenolformaldehyde resins, polyester resins, urethane resins, and mixturesthereof.
 40. The consolidation fluid of claim 38 wherein the silanecoupling agent is selected from the group consisting ofN-2-(aminoethyl)-3-aminopropyl trimethoxysilane,3-glycidoxypropyltrimethoxysilane, and mixtures thereof.
 41. Theconsolidation fluid of claim 38 wherein the surfactant is selected fromthe group consisting of alkyl phosphonate surfactants, ethoxylated nonylphenol phosphonate esters, cationic surfactants, nonionic surfactants,and mixtures of one or more cationic and nonionic surfactants.
 42. Theconsolidation fluid of claim 38 wherein the consolidation fluid isfoamed.
 43. The consolidation fluid of claim 38 wherein the emulsifyingagent is selected from the group consisting of surfactants, proteins,hydrolyzed proteins, lipids, glycolipids, nano-sized particulates, andfumed silica is used to emulsify the resin.
 44. The consolidation fluidof claim 38 wherein the emulsified resin is present in the consolidationfluid in an amount from about 1% w/v to about 10% w/v.
 45. Theconsolidation fluid of claim 38 wherein the surfactant is a mixture ofan amphoteric surfactant present in an amount from about 30% to about45% by weight of the surfactant mixture and an anionic surfactant in anamount from about 55% to about 70% by weight of the surfactant mixture.